The present invention relates to measurement of flow of a gas. More specifically, the invention relates to the effects of water vapor present in the flow on such measurements.
Government regulations are placing increasing constraints on energy producers to account for greenhouse gas content during production. For example, the natural gas industry must account for CO2 emissions. In many applications there is water vapor present in the pipe which is not identified during a gas chromatograph analysis of the “dry gas” composition.
Natural gas mixtures flowing from wells typically consist of a combination of a number of gas species. Some are hydrocarbon gases such as methane, ethane, propane, etc. which are the desirable products. Others are by-products such as carbon dioxide, nitrogen, etc. which have less value. One of these by-product gases, carbon dioxide, is particularly important in that it is one of the “greenhouse gases” that contributes to global warming. There is increasing interest through government regulations in quantifying the emission of carbon dioxide. In order to comply with such regulations natural gas producers are becoming increasingly interested in the amount of carbon dioxide they pump out of wells.
One of the things that is done to reduce the uncertainty in natural gas flow measurement is to obtain an accurate gas composition by analyzing samples of the gas from a given well. These samples are typically obtained with some regularity at the beginning of the life of a well. However, the frequency of sampling decreases as it becomes apparent that the gas composition can be considered to be fixed. It is important to note that the gas composition is obtained by taking a sample of the gas to a laboratory and analyzing it with a gas chromatograph or other such devices. The resulting composition is what is considered a “dry gas” composition. This means that there is no water vapor content in the gas. The equation of state used in the natural gas industry, AGA (American Gas Associate) Report No. 8, can account for water vapor.
However, this is rarely included in gas composition reports. In fact, the six example compositions given in AGA Report No. 8 contain no water content.
As the pressure in a well reduces with age due to depletion of the gas in the field, measures such as steam injection are often used to force gas and oil from the ground. When this is done the gas produced now contains water vapor in addition to the gases present in the dry gas composition. This means that in a given volume some of the dry gas is replaced by water vapor. Since the flow rate is measured based on the dry gas composition the measurements will overstate the amount of all gases, including carbon dioxide.